Removal of kinetic hydrate inhibitors

ABSTRACT

A method includes receiving a water stream from a hydrocarbon production facility, the water stream having a first concentration of a kinetic hydrate inhibitor (KHI); flowing the water stream through a heat exchanger to heat the water stream to a target temperature; mixing the heated water stream with a treatment chemical to form a two-phase mixture, the treatment chemical having an affinity for the KHI; flowing the two-phase mixture into a separator; and physically separating the two-phase mixture into a first phase and a second phase, the first phase including water and having a second concentration of the KHI less than the first concentration, and the second phase including the KHI and the treatment chemical, the density of the second phase being less than the density of the first phase.

CLAIM OF PRIORITY

This application is a Divisional of and claims the benefit of priorityto U.S. patent application Ser. No. 15/270,710, filed on Sep. 20, 2016,which claims priority to U.S. Provisional Patent Application Ser. No.62/222,547, filed on Sep. 23, 2015, the entire contents of which arehereby incorporated by reference.

BACKGROUND

Hydrates are crystalline solids that form in the presence of water andcertain types of light hydrocarbon molecules. Hydrate formation canoccur in fluid streams containing hydrocarbons and water, such as fluidstreams from hydrocarbon production wells or processing plants. Hydratescan accumulate on inner walls of pipes or fluid receptacles, blockingthe flow of the fluid stream there through and fouling equipment. Toinhibit hydrate formation, hydrate inhibitors, such as kinetic hydrateinhibitors (KHIs), can be added to the fluid stream. KHIs aresubstances, such as water soluble polymers, that inhibit the formationof hydrates, for example, by slowing the nucleation or growth of hydratecrystals. Treating a fluid stream with KHI thus enables fluid streams topass along a flow path with reduced hydrate formation.

SUMMARY

In a general aspect, a method includes receiving a water stream from ahydrocarbon production facility, the water stream having a firstconcentration of a kinetic hydrate inhibitor (KHI); flowing the waterstream through a heat exchanger to heat the water stream to a targettemperature; mixing the heated water stream with a treatment chemical toform a two-phase mixture, the treatment chemical having an affinity forthe KHI; flowing the two-phase mixture into a separator; and physicallyseparating the two-phase mixture into a first phase and a second phase,the first phase including water and having a second concentration of theKHI less than the first concentration, and the second phase includingthe KHI and the treatment chemical, the density of the second phasebeing less than the density of the first phase.

Embodiments can include one or more of the following features.

Receiving the water stream includes receiving a fluid stream from thehydrocarbon production facility; and separating the fluid stream into ahydrocarbon stream and the water stream.

The method includes separating the fluid stream into the hydrocarbonstream, the water stream, and a gas stream.

The target temperature is based on a characteristic of the KHI, acharacteristic of the treatment chemical, or both.

The received water stream is at a first temperature, and wherein thetarget temperature is at least 5° F. greater than the first temperature.

The target temperature is between about 70° F. and about 160° F.

Flowing the water stream through a heat exchanger includes heating thewater stream to a temperature sufficient to cause at least some of theKHI to precipitate from the water stream.

Mixing the heated water stream with a treatment chemical includes addingthe treatment chemical to the water stream such that a ratio of thetreatment chemical to the KHI is between about 1 and about 3.

Physically separating the two-phase mixture includes performing agravity separation.

The method includes processing the first phase to remove residual KHI.

Processing the first phase includes generating a third phase having athird concentration of KHI, the third concentration being less than thesecond concentration.

The method includes processing the first phase in a polisher.

The method includes removing the KHI from the second phase.

The method includes returning the separated KHI to an upstreamdestination in the hydrocarbon production facility for reuse.

The method includes returning the second phase to an upstreamdestination in the hydrocarbon processing or production facility forreuse.

The treatment chemical is substantially immiscible with water.

The treatment chemical includes a non-polar substance.

The treatment chemical includes a functional group that has an affinityfor a component of the KHI.

The second concentration is at least about 40% less than the firstconcentration, at least about 50% less than the first concentration, orat least about 60% less than the first concentration.

A cloud point temperature of the water phase is at least about 40° C.

A fouling temperature of the water phase is at least about 90° C.

Mixing the heated water stream with a treatment chemical includes mixingthe heated water stream, the treatment chemical, and an organic acid.

Mixing the heated water stream with a treatment chemical includes mixingthe heated water stream, the treatment chemical, and a saline solution.

In a general aspect, a system includes a fluid inlet configured toreceive a water stream from a hydrocarbon production facility, the waterstream having a first concentration of a kinetic hydrate inhibitor(KHI); a heat exchanger configured to heat the water stream to a targettemperature; a mixer configured to receive the heated water stream and atreatment chemical, the treatment chemical having an affinity for theKHI, wherein the water stream and the treatment chemical are mixed inthe mixer to form a two-phase mixture; and a separator configured tophysically separate the two-phase mixture into a first phase and asecond phase, the first phase including water and having a secondconcentration of the KHI less than the first concentration, and thesecond phase including the KHI and the treatment chemical, the densityof the second phase being less than the density of the first phase.

Embodiments can include one or more of the following features.

The system includes a separator configured to separate a fluid streamreceived from the hydrocarbon production facility into a hydrocarbonstream and the water stream.

The separator is configured to separate the fluid stream into thehydrocarbon stream, the water stream, and a gas stream.

The target temperature is based on a characteristic of the KHI, acharacteristic of the treatment chemical, or both.

The received water stream is at a first temperature, and wherein theheat exchanger is configured to heat the water stream to a temperatureat least 5° F. greater than the first temperature.

The target temperature is between about 70° F. and about 160° F.

The heat exchanger is configured to heat the water stream to atemperature sufficient to cause at least some of the KHI to precipitatefrom the water stream.

The treatment chemical is substantially immiscible with water.

The mixer includes a static mixer.

The separator includes a gravity separator.

The system includes a polisher configured to remove residual KHI fromthe first phase.

The polisher is configured to generate a third phase having a thirdconcentration of KHI, the third concentration being less than the secondconcentration.

The system includes a pump to provide the second phase to an upstreamdestination in the hydrocarbon production facility for reuse.

The system includes a KHI separation component configured to remove KHIfrom the second phase.

The system includes a pump to provide the removed KHI from theseparation component to an upstream destination in the hydrocarbonproduction facility for reuse.

The approaches described here can have one or more of the followingadvantages. Kinetic hydrate inhibitors (KHIs) can be removed from awater stream, thus reducing sludge formation and deposition inprocessing or disposal systems that handle the water stream. KHI removedfrom the water stream can be regenerated and reused, thus reducing costsand reducing the environmental impact of hydrate removal.

Other features and advantages are apparent from the followingdescription and from the claims.

BRIEF DESCRIPTION OF DRAWINGS

FIGS. 1-3 are a block diagrams of systems for kinetic hydrate inhibitorremoval.

FIG. 4 is a flow chart.

DETAILED DESCRIPTION

Kinetic hydrate inhibitors (KHIs) can be added to a fluid stream, suchas a fluid stream from a hydrocarbon production well or processingplant, in order to inhibit formation of hydrates in the fluid stream.KHIs are substances that are soluble in water and that are capable ofslowing the rate of hydrate nucleation. After the fluid stream isprocessed, KHIs remain dissolved in the produced water. In somesituations, KHIs can degrade or precipitate out of solution. Forinstance, KHI degradation or precipitation can occur upon exposure tohigh temperatures or a high salinity environment, for example, duringprocessing of the produced water or during mixing of the produced waterwith water from another source. KHI degradation or precipitation canlead to sludge formation which fouls the water phase and results insludge deposition, for example, in water pipes or water processingfacilities.

We describe here an approach to removing KHIs dissolved in an aqueousphase, such as a sour water stream, thus reducing the degree of sludgeformation in downstream water processing facilities. In the approachdescribed here, a treatment chemical that is immiscible with water andthat has a high affinity to one or more KHI components (for example,polymers) is mixed with an aqueous phase containing KHI. The treatmentchemical, which forms a separate phase from the aqueous phase, extractsone or more KHI components from the aqueous phase into the treatmentchemical phase. The two-phase liquid is then separated into an aqueousphase, which has a lower concentration of KHI than the original aqueousphase, and a treatment chemical phase containing KHI. The aqueous phasewith reduced KHI concentration can be further processed with a loweredrisk of fouling and sludge deposition. The treatment chemical phasecontaining KHI can be disposed of or can be further processed, forexample, for regeneration or reuse.

Referring to FIG. 1, an example system 10 removes KHI from a fluidstream 100. A KHI formulation can be composed of one or more types ofpolymers, such as water soluble polymers. For example, KHI polymers caninclude polymers or copolymers of acrylamides, maleimides,vinylpyrrolidone, vinylcaprolactam, or other types of polymers orcopolymers. In some cases, KHI polymers are dissolved in a low molecularweight solvent, such as an alcohol, a glycol (for example, monoethyleneglycol (MEG)), or a glycol either (for example, ethylene glycolmonobutyl ether (EGBE)), or another solvent, prior to being added to thefluid stream.

Fluid stream 100 can be a stream of hydrocarbons and water, for example,from a hydrocarbon production well to which KHI was added to inhibithydrate formation. For instance, fluid stream 100 can include about 1%KHI, about 2% KHI, about 3% KHI, or about 3.5% KHI by mass.

A separator 200 treats fluid stream 100 at conditions sufficient toseparate fluid stream 100 into three phases: a gas phase 210, ahydrocarbon phase 220, and an aqueous phase 230. The separator 200 canoperate at a pressure of between about 700 psig and about 1500 psig,such as about 700 psig, about 800 psig, about 900 psig, about 1000 psig,about 1100 psig, about 1200 psi, about 1300 psi, about 1400 psig, orabout 1500 psig. The separator 200 can operate at a temperature ofbetween about 40° F. and about 120° F., such as about 40° F., about 50°F., about 60° F., about 70° F., about 80° F., about 90° F., about 100°F., about 110° F., or about 120° F. The separator 200 can treat fluidstream 100 for between about 5 minutes and about 30 minutes, such asabout 5 minutes, about 10 minutes, about 15 minutes, about 20 minutes,about 25 minutes, about 30 minutes, or another amount of time.

Gas phase 210, which can include light hydrocarbons such as methane,ethane, propane, butane, or other light hydrocarbons, and gases such ascarbon dioxide, nitrogen, or water vapor, exits the top of separator200. Hydrocarbon phase 220, which can include heavier hydrocarbons, suchas aromatics, resins, or other heavier hydrocarbons, exits the bottom ofseparator 200. Gas phase 210 and hydrocarbon phase 220 are processed asappropriate, for example, for consumption, sale, or disposal. Aqueousphase 230, which includes water and KHI, exits the bottom of separator200. Because KHI polymers are generally water soluble, aqueous phase 230contains most or all of the KHI originally present in fluid stream 100,which gas phase 210 and hydrocarbon phase 220 contain little or no KHI.In some examples, separator 200 can separate fluid stream 100 into twophases rather than three phases, for example, into a hydrocarbon phaseand an aqueous phase.

Aqueous phase 230 is heated by a heat exchanger 300, such as a heater,in order to bring aqueous phase 230 to a target temperature for KHIremoval. The target temperature for KHI removal can depend on factorssuch as the identity or characteristics of the KHI polymers, theidentity or characteristics of the treatment chemical (described below)used to extract KHI, or other factors, and can be determined on acase-by-case basis, for example, experimentally or based on knowledge ofthe KHI polymers or the treatment chemical or both. Without being boundby theory, it is believed that heating aqueous phase 230 can cause someor all of the dissolved KHI polymers to precipitate from solution, thusfacilitating the downstream removal of KHI from aqueous phase 230.

In some examples, heat exchanger 300 heats aqueous phase 230 from a lowtemperature to higher temperature, such as to a temperature of betweenabout 70° F. and about 160° F., for instance, to a temperature of about70° F., about 80° F., about 90° F., about 100° F., about 110° F., about120° F., about 130° F., about 140° F., about 150° F., or about 160° F.In some examples, heat exchanger 300 raises the temperature of aqueousphase 230 by at least about 5° F., for instance, at least about 10° F.,at least about 20° F., at least about 30° F., at least about 40° F., atleast about 50° F., at least about 60° F., at least about 70° F., atleast about 80° F., at least about 90° F., or at least about 100° F.Heat exchanger 300 can be, for instance, a shell and tube heat exchangeror another type of heat exchanger.

The heated aqueous phase 230 flows from heat exchanger 300 into a mixer400, such as a static mixer, a mechanical mixer, or another type ofmixer. Mixer 400 can operate at a pressure of between about 700 psig andabout 1500 psig, such as about 700 psig, about 800 psig, about 900 psig,about 1000 psig, about 1100 psig, about 1200 psi, about 1300 psi, about1400 psig, or about 1500 psig. Mixer 400 can operate at the temperatureof the incoming aqueous phase 230, for instance, at a temperature ofabout 70° F., about 80° F., about 90° F., about 100° F., about 110° F.,about 120° F., about 130° F., about 140° F., about 150° F., or about160° F. One or more treatment chemicals 130 are also introduced intomixer 400. The quantity of treatment chemicals 130 introduced into mixer400 can depend on the amount of KHI in aqueous phase 230. For instance,treatment chemicals 130 can be introduced such that the ratio by weightof treatment chemicals 130 to KHI is between about 1 and about 5, suchas about 1, about 1.5, about 2, about 2.5, or about 3.

A treatment chemical is a substance, such as an organic compound, thatis substantially or completely immiscible with water and that has a highaffinity for one or more types of KHI polymers in aqueous phase 230.Treatment chemicals are discussed in more detail below. When treatmentchemicals 130 are mixed with aqueous phase 230, a two-phase liquidmixture 410 is formed, with the water in one phase and the treatmentchemicals in the second phase. Because of the high affinity of treatmentchemicals 130 for the KHI polymers, the KHI polymers are extractedentirely or in part from the water phase into the treatment chemicalphase, and thus the second phase includes both treatment chemicals andKHI polymers. As a result, the water phase becomes largely or completelyfree of KHI polymers. For instance, an interaction between a functionalgroup on the treatment chemical and a functional group on a KHI polymercan be sufficiently strong as to cause the KHI polymer to be extractedfrom aqueous phase 230 into the treatment chemical phase. Becausetreatment chemicals 130 are highly effective solvents for KHI polymers,only a small amount of treatment chemicals 130 can be used to causesignificant displacement of KHI polymers from aqueous phase 230 into thetreatment chemical phase.

Treatment chemical driven extraction of KHI from aqueous phase 230 canbe achieved because of the relative solubility of KHI in each of the twoimmiscible liquids in the system, the water and the treatment chemicals.KHI is distributed between aqueous phase 230 and the treatment chemicalphase according to its solubility in each phase. Because treatmentchemicals 130 have such a high affinity for the KHI polymers, all ormost of the KHI dissolves preferentially in the organic treatmentchemical phase. Mixer 400 provides sufficient time to achieve propermixing of the aqueous phase 230 with the treatment chemical phase, thusallowing sufficient contact between treatment chemicals and KHI andallowing KHI to be distributed into the two phases according to itssolubility.

The elevated temperature of the aqueous phase 230 resulting from heatingin heat exchanger 300 helps to encourage the removal of KHI from aqueousphase 230 through the use of the treatment chemical. The elevatedtemperature can also facilitate separation of water and treatmentchemical with KHI in separator 500, discussed below. This solventextraction of KHI from the water phase into the treatment chemical phasereduces the concentration of KHI in the aqueous phase. In some cases,when KHI precipitation begins in heat exchanger 300, the addition oftreatment chemicals 130 to aqueous phase 230 enhances extraction of KHIfrom aqueous phase 230.

The role of separator 200 in removing hydrocarbons from aqueous phase230 can help increase the effectiveness of treatment chemicals 130 inextracting KHI from the water phase. In particular, the affinity of KHIto treatment chemicals 130 is reduced with increasing amounts of liquidhydrocarbon present in a liquid mixture. Thus, by removing hydrocarbonsprior to introducing treatment chemicals 130, any potential reduction intreatment chemical effectiveness due to hydrocarbons can be mitigated.

A two-phase mixture 410 exits mixer 400 and enters a three-phaseseparator 500. In three-phase separator 500, the aqueous phase and thetreatment chemical phase are physically separated, a process sometimesreferred to as liquid-liquid separation. For instance, the three-phaseseparator 500 can be a gravity separator that uses gravity settling toseparate the denser aqueous phase from the less dense treatment chemicalphase. Other types of physical separation, such as centrifugalseparation, can also be used. Three-phase separator 500 can operate at apressure of between about 700 psig and about 1500 psig, such as about700 psig, about 800 psig, about 900 psig, about 1000 psig, about 1100psig, about 1200 psi, about 1300 psi, about 1400 psig, or about 1500psig. Three-phase separator 500 can operate at a temperature of betweenabout 70° F. and about 160° F., such as about 70° F., about 80° F.,about 90° F., about 100° F., about 110° F., about 120° F., about 130°F., about 140° F., about 150° F., or about 160° F. It is believed thatthe heating of aqueous phase 230 by heat exchanger 300 helps facilitateefficient separation of two-phase mixture 410 by three-phase separator500.

Variable settling rates control the separation of two-phase mixture 410in three-phase separator 500. Two-phase mixture 410 can be retained inthree-phase separator 500 for a time sufficient to remove a targetamount of KHI from the aqueous phase. For instance, two-phase mixture410 can be retained for between about 6 hours and about 24 hours, suchas about 6 hours, about 8 hours, about 10 hours, about 12 hours, about16 hours, about 20 hours, about 24 hours, or another amount of time. Insome examples, when two-phase mixture 410 is retained in three-phaseseparator 500 for a shorter amount of time, such as about 6 hours, aseparation of about 70-100%, such as about 70%, about 80%, about 90%, orabout 100%, can be achieved. In some examples, two-phase mixture 410 canbe retained for a longer period of time, such as about 24 hours, toachieve a more complete separation of about 80-100%, such as about 80%,about 90%, or about 100%.

In some examples, organic acids can be added to mixer 400 in order tofurther facilitate KHI extraction into the treatment chemical phase. Theacidity of aqueous phase 230 can be slightly increased, such as to a pHin the range of about 3 to about 7, by introducing a mild acid such asorganic citric acid or formic acid. This slight increase in pH promotesthe precipitation of KHI from aqueous phase 230, thus making KHI removaleasier, particularly when a gravity settling approach to separation isemployed by three-phase separator 500. The efficiency resulting from theaddition of organic acids can allow the dimensions of three-phaseseparator 500 to be reduced, thus reducing costs for KHI separationprocesses. For instance, the retention time of two-phase mixture 410 inthree-phase separator can be reduced by between about 2 hours and about4 hours with the addition of organic acids.

In some examples, saline water can be added to mixer 400 in order tofurther facilitate KHI extraction into the treatment chemical phase. Byadding saline water to increase the salinity of the aqueous phase 230,such as to a salinity of between about 5% and about 15% by mass, therate of physical separation in three-phase separator 500 can beincreased due to a greater difference in density between the lesstreatment chemical phase and the more dense saline water phase. Forinstance, substantially complete separation can be achieved within about2-4 hours. The efficiency resulting from the addition of saline watercan allow the dimensions of three-phase separator 500 to be reduced,thus reducing costs for KHI separation processes.

Three separate streams exit three-phase separator 500: a KHI stream 510composed of the treatment chemicals and KHI polymers for which thetreatment chemicals have an affinity, a water stream 520 composed ofwater with a reduced concentration of KHI, and vapor stream 530containing light hydrocarbon components vaporized as a result of heatingby heat exchanger 300. In some examples, water stream 520 contains atleast about 40% by weight less KHI than aqueous phase 230, for example,at least about 50% less, at least about 60% less, at least about 70%less, at least about 80% less, at least about 90% less, or at leastabout 100% less KHI than aqueous phase 230. Vapor stream 530 can bereturned to the process or routed elsewhere for disposal.

In some examples, water stream 520 is routed through a polisher 600,which removes any residual KHI from the water. The operating parametersof polisher 600 depend on the physical properties of the treatmentchemical. For instance, whether polisher 600 is used and the operatingparameters of polisher 600 can depend on the amount of KHI removed byseparation in three-phase separator 500, the amount of time appropriateto remove a desired amount of KHI by separation in three-phase separator500, the impact of residual KHI in water stream 520 on disposal orfurther processing, or other factors. A water stream 620, which is has areduced concentration of KHI and treatment chemicals as compared towater stream 520, exits polisher 600 and flows to another system for useor further processing. In some examples, water stream 620 contains atleast about 40% by weight less KHI than water stream 520, for example,at least about 50% less, at least about 60% less, at least about 70%less, at least about 80% less, at least about 90% less, or at leastabout 100% less KHI than water stream 520. For instance, water stream620 can have a water quality that is suitable for re-injection into adisposal well or for further processing, such as in a hybrid KHI/MEGsystem.

A KHI stream 610, composed of residual KHI and treatment chemicalsremoved by polisher 600, joins KHI stream 510. Both KHI streams 510, 610are pumped by a pump 700. In some cases, KHI streams 510, 610 are pumpedto a disposal destination 710. In some cases, KHI streams 510, 610 arepumped to a treatment system, for example, for recovery and reuse of theKHI or the treatment chemicals or both. For instance, up to 100% of thetreatment chemicals can be recovered in the disposal destination, suchas between 80% and 100%, such as 80%, 80%, 90%, 95%, or 100% of thetreatment chemicals.

Referring to FIG. 2, in an example system 50, KHI is removed from fluidstream 100 as described above. KHI streams 510, 610, which contain KHIand treatment chemicals, are joined into a common stream 720 and pumpedby pump 700 to a separation unit 800, which separates KHI from treatmentchemicals. In some examples, a steam stream 730 is routed to a disposaldestination. Without being bound by theory, it is believed that theinjection of condensate 830 into separation unit 800 reduces theaffinity of KHI to treatment chemicals, thus driving the dissolved KHIout of the phase including treatment chemicals. For instance, a ratio ofcondensate 830 to treatment chemical of at least one can reduce theaffinity of KHI to treatment chemicals. The condensate can be, forinstance, condensate from a hydrocarbon processing plant. Treatmentchemicals are sent to another system for disposal or for reprocessing atdownstream processing facilities. Recovered KHI 810 is returned tosystem 50 for reuse. For instance, recovered KHI 810 is introduced tofluid stream 100 in order to inhibit hydrate formation. In someexamples, up to about 70% of the initially introduced KHI can berecovered, such as about 40%, about 50%, about 60%, or about 70%.

Referring to FIG. 3, in an example system 60, KHI is removed from fluidstream as described above. KHI streams 510, 610, which contain KHI andtreatment chemicals, are joined into a recycle stream 850 and returnedto system 50 for reuse. For instance, recycle stream 850, which containsboth KHI and treatment chemicals, is introduced to fluid stream 100 inorder to inhibit hydrate formation. Without being bound by theory, it isbelieved that the presence of hydrocarbons in fluid stream 100 causes areduction in the affinity of KHI to treatment chemicals, and thus thepresence of treatment chemicals in fluid stream 100 is not believed toaffect the role of KHI in inhibiting hydrate formation. For instance,the affinity of KHI to treatment chemicals may become insignificant whenthe ratio of liquid hydrocarbons to treatment chemicals in fluid stream100 exceeds a certain value, such as when the ratio is greater than one.In this case, the presence of treatment chemicals in fluid stream 100 isnot believed to be able to extract KHI from aqueous solution, thusallowing the KHI to inhibit hydrate formation in fluid stream 100.Downstream, such as when hydrocarbons are removed in separator 200, theaffinity of KHI to treatment chemicals is increased and the treatmentchemicals are thus able to draw KHI out of aqueous solution.

In system 60, additional treatment chemicals 130 can be introduced intomixer 400, for instance, in order to increase the ratio of treatmentchemicals to KHI. In some cases, the amount of treatment chemicals issufficient and no additional treatment chemicals 130 are added intomixer 400.

KHI polymers can be organic, water miscible, or both. Example KHIpolymers can include, for instance, one or more of the followingpolymers or combinations or derivatives thereof: poly(vinylcaprolactam)(PVCap); polyvinylpyrrolidone; poly(vinylvalerolactam);poly(vinylazacyclooctanone); co-polymers of vinylpyrrolidone andvinylcaprolactam; poly(N-methyl-N-vinylacetamide); copolymers ofN-methyl-N-vinylacetamide and acryloyl piperidine; co-polymers ofN-methyl-N-vinylacetamide and isopropyl methacrylamide; co-polymers ofN-methyl-N-vinyl acetamide and methacryloyl pyrrolidine; copolymers ofacryloyl pyrrolidine and N-methyl-N-vinylacetamide; acrylamide/maleimideco-polymers such as dimethylacrylamide (DMAM) copolymerized with, forexample, maleimide (ME), ethyl maleimide (EME), propyl maleimide (PME),or butyl maleimide (BME); acrylamide/maleimide co-polymers such asDMAM/methyl maleimide (DMAM/MME) and DMAM/cyclohexyl maleimide(DMAM/CHME); N-vinyl amide/maleimide co-polymers such asN-methyl-Nvinylacetamide/ethyl maleimide (VIMAlEME); lactam maleimideco-polymers such as vinylcaprolactam ethylmaleimide (VCap/EME);polyvinyl alcohols; polyamines; polycaprolactams; or polymers orco-polymers of maleimides or acrylamides.

A KHI formulation can include one or more KHI polymers and one or morecompounds that enhances the performance or solubility of the KHIpolymers. The performance- or solubility-enhancing compounds caninclude, for instance, alcohols such as 2-butoxyethanol,(2-methoxymethylethoxy) propanol, or ethanediol.

A KHI formulation can include one or more types of polymers. In someexamples, all of the types of polymers in a given KHI formulation can beremoved by a single treatment chemical. In some examples, fewer than allof the types of polymers in a KHI formulation can be removed by a singletreatment chemical. For instance, a single treatment chemical may removeat least 50% of one of the types of polymers in a KHI formulation, suchas at least about 60%, at least about 70%, at least about 80%, at leastabout 90%, at least about 95%, or about 100% of one of the types ofpolymers, while removing little to none of the other type(s) of polymersin the KHI formulation.

To remove multiple types of polymers in a KHI formulation, such as allof the types of polymers, an aqueous phase containing KHI can be treatedby multiple treatment chemicals, either simultaneously or in series. Forinstance, treatment by multiple treatment chemicals may remove at least50% by weight of some or all of the types of polymers in a KHIformulation, such as at least about 60%, at least about 70%, at leastabout 80%, at least about 90%, at least about 95%, or about 100% of someor all of the types of polymers. In some cases, not all of the types ofpolymers in a KHI formulation are removed from the aqueous phase. Forinstance, polymers that do not tend to precipitate into sludge may notbe removed.

A treatment chemical is a substance, such as an organic compound, thatis substantially or completely immiscible with water and that has a highaffinity for one or more types of KHI polymers. For instance, atreatment chemical can have a miscibility with water of less than about10% by mass, such as about 0.1%, about 0.5%, about 1%, about 1.5%, about2%, about 3%, about 4%, about 5%, about 6%, about 7%, about 8%, about9%, or about 10% miscibility with water. A treatment chemical can be anon-polar substance that includes a functional group with an affinityfor a functional group of one or more of the types of KHI polymers. Forinstance, a treatment chemical can include a hydrophobic portion, suchas a hydrocarbon chain; and a hydrophilic portion, such as a portioncontaining a hydroxyl (—OH) group. In some examples, a treatmentchemical can be a fatty alcohol based substance.

Treatment chemicals can include alcohols with sufficiently large carbonnumber to be immiscible with water, such as alcohols with at least threecarbon atoms or alcohols with between three carbon atoms and twelvecarbon atoms, for instance, alcohols with three carbon atoms, fourcarbon atoms, five carbon atoms, six carbon atoms, seven carbon atoms,eight carbon atoms, nine carbon atoms, ten carbon atoms, eleven carbonatoms, or twelve carbon atoms. The alcohol can include an alkyl group,an allyl group, a cyclic group, or a benzyl group. For instance, thealcohol can be butanol, pentanol, hexanol, or octanol.

Treatment chemicals can include glycol ethers with sufficiently largecarbon number to be immiscible with water, such as glycol ethers with atleast six carbon atoms. The glycol ether can include a hydrocarbon groupsuch as an alkyl group, an allyl group, a cyclic group, a benzyl group,or a phenol group. For instance, the glycol ether can be ethylene glycolmonoethyl ether, ethylene glycol monopropyl ether, ethylene glycolmonobutyl ether, ethylene glycol monophenyl ether, ethylene glycolmonobenzyl ether, diethylene glycol monomethyl ether, diethylene glycolmonoethyl ether, or diethylene glycol mono-n-butyl ether.

In some examples, treatment chemicals can include a first organiccompound, such as an alcohol or a glycol ether; and one or more secondorganic compounds of lower density than the first organic compound. Thesecond organic compound can be a hydrocarbon, such as a hydrocarbonhaving a carbon number less than or equal to the carbon number of thefirst organic compound. The lower density second organic compound orcompounds can assist in the separation of the mixture of treatmentchemicals 130 and aqueous phase 230 into two phases. For instance, thesecond organic compound can include butane, pentane, hexane, or octane.

Referring to FIG. 4, in a general process for KHI removal, a fluidstream that has been treated with KHI, for example, in order to inhibithydrate formation, is separated into a gas phase, a hydrocarbon phase,and an aqueous phase (30). Most or all of the KHI originally present inthe fluid stream is contained in the aqueous phase, while the gas andhydrocarbon phases generally contain little or no KHI. The aqueous phasecontaining KHI is heated to a target temperature for KHI removal (32),for example, in a heat exchanger. For instance, the target temperaturecan be based on the identity or characteristics of the KHI polymers, theidentity or characteristics of the treatment chemical used to extractKHI, or other factors. Heating of the aqueous phase can cause some orall of the dissolved KHI polymers to precipitate from solution, thusfacilitating downstream removal of KHI from the aqueous phase andliquid/liquid phase separation.

The heated aqueous phase flows to a mixer, where the aqueous phase ismixed with one or more treatment chemicals to form a two-phase liquidmixture (34). The treatment chemicals are immiscible with water andexhibit a high affinity for one or more types of KHI polymers in theaqueous phase. During the mixing process, KHI polymers are thusextracted from the aqueous phase into the treatment chemical phase (36),reducing the concentration of KHI in the aqueous phase. The elevatedtemperature of the aqueous phase helps to encourage the removal of KHIfrom the aqueous phase and liquid/liquid phase separation.

The two-phase liquid mixture flows into a separator where the mixture isphysically separated (38), for example, by gravity settling, in order toseparate the more dense water phase from the less dense treatment phaseincluding KHI. The treatment chemical phase is disposed of or processedfor KHI recovery and reuse (42). In some examples, the water phase isfurther processed, for example, in a polisher, to remove residual KHI(40). For instance, the water phase can be further processed in thepolisher if a target level of KHI removal cannot be achieved in theseparator in a desired amount of time. The water exiting the polisher,which has a reduced level of KHI, is sent to other systems for use orfurther processing. Residual KHI removed from the water phase in thepolisher is disposed of or processed for KHI recovery and reuse (42).For instance, KHI can be recovered and reused to treat a fluid stream toinhibit hydrate formation.

Example—Treatment Chemical Screening and Assessment

Four treatment chemicals (TCs) were screened for effectiveness inremoving two types of KHI from aqueous solution. Based on the screeningresults, two TCs were selected for further assessment, includingassessment of the effects of temperature, salinity, solvents, andre-treatment on the KHI removal effectiveness of each TC.

In the screening phase, four TCs that are known to effectively removeKHI from water were screened to determine their removal effectivenessfor two specific KHI systems. The TCs screened in this example arereferred to as TC7, TC7A, TCBA, and TC8, which are commerciallyavailable products, such as those described in PCT publication WO2013/121217, the contents of which are incorporated here by reference intheir entirety.

The first KHI system (referred to as System 1) contained 2.5% by mass ofa first KHI formulation in an aqueous solution. The first KHIformulation was Baker EK1398 HIW KHI, with a composition of 30-60%diethylene glycol monoethyl ether, 10-30% 2-butoxyethanol, and 10-30%alkyl substituted polyamide copolymer.

The second KHI system (referred to as System 2) contained 5.0% by massof a second, different KHI formulation in an aqueous solution. Thesecond KHI formulation was Nalco-Champion EC981A KHI, with a compositionof 10-30% ethylene glycol monoethyl ether, 10-30%(2-methoxymethylethoxy) propanol, and 10-30% ethanediol.

In the screening analysis, samples from System 1 and System 2 were eachtreated with one of the TCs listed above. For each sample, watercontaining the corresponding KHI formulation at a concentration ofbetween about 2.5% and about 5% by weight was stirred in a beaker with amagnetic stirrer at room temperature. A TC was injected into theKHI-containing water and the time until a clear light liquid phaseappeared was measured. The ratio of injected TC to KHI in the sampleswas between about 1 and about 3 by weight.

Following TC treatment, the mass percent of KHI removed from aqueoussolution was determined by UV-visible spectroscopy. UV-vis spectroscopyis generally sensitive to KHI polymers yet largely unaffected by commonKHI solvents, such as monoethylene glycol (MEG) or ethylene glycol butylether (EGBE) in which KHI polymers are sometimes dissolved. UV-visspectroscopy can thus be a useful and accurate tool for KHI removalanalysis.

A UV-vis absorbance spectrum of a sample prior to treatment (sometimesreferred to as the calibration spectrum) was compared with a UV-visabsorbance spectrum of the same sample following TC treatment. Thedifference between the calibration spectrum and the post-treatmentspectrum was used to determine the percentage of KHI remaining inaqueous solution following TC treatment and accordingly the percentageof KHI removed from aqueous solution as a result of TC treatment.Because analysis of UV-vis absorbance spectra is based on a comparisonbetween the calibration spectrum and the post-treatment spectrum, thespecific polymer fraction of a particular KHI is not necessary in orderto determine the percentage of KHI removed from solution by a TCtreatment.

In some cases, gravimetric analysis was conducted to confirm the KHIremoval results determined by UV-vis spectroscopy. Treated samples weredried and the remaining solids weight to determine the weight of KHIremaining following TC treatment. As a control, an untreated sample fromeach of System 1 and System 2 was also dried and weighed to establish abaseline solids content against which the post-treatment samples werecompared.

The post-treatment cloud point temperature and fouling temperature (ifany) were also determined for each sample. The cloud point temperatureof a sample is the temperature at which waxes in the sample begin tosolidify, giving the sample a cloudy appearance. The fouling temperatureof a sample is the temperature above the cloud point temperature atwhich coagulated polymer is first observed. Fouling propensity, cloudpoint, and fouling point tests were conducted using an atmosphericpressure heated glass visual cell method with a laser intensityautomated cloud point apparatus. The laser intensity automated cloudpoint apparatus measures changes in sample transparency as a function oftemperature during heating or cooling, from which the cloud pointtemperature can be determined. Visual observation was used to determinethe temperature at which fouling of each sample by solids or semi-solidsoccurred. In visual observation tests, samples were observed at 10° C.intervals above the cloud point temperature to identify the onset ofsolid or semi-solid build-up.

Results of the screening analysis of TC7, TC7A, TCBA, and TC8 for System1 samples are shown in Table 1. KHI removal from System 1 samples wasgenerally in the range of 32-39% for TC7, TCBA, and TC8. TC7A removed upto 93% of KHI, as confirmed by two separate analyses.

TABLE 1 TC screening for System 1. Aq. Polymer KHI dose polymer removedPTCPT PTFT System (mass %) (mass %) TC (mass %) (° C.) (° C.) System 12.5 0.74 TC7 39 50 N/A KHI only 2.5 0.74 TC7A 84-93 >90 >90 2.5 0.74TCBA 37 60 N/A 2.5 0.74 TC8 32 50 N/A

The identity of the KHI polymers in the System 1 samples is unknown. Theresults shown in Table 1 indicate that the KHI in System 1 may becomposed of two different polymers, one of which is relatively easy toremove and the other of which is more difficult to remove. Only TC7Asucceeded in removing both types of KHI polymers from the System 1samples. The System 1 samples treated with TC7A also showed neitherclouding nor fouling at temperatures up to 90° C., which is a furtherindication that high levels of KHI were removed by TC7A treatment.

Results of the screening analysis of TC7, TC7A, TCBA, and TC8 for System2 samples are shown in Table 2. TC7A and TCBA each removed about 63-64%of KHI. The lowest level of KHI removal was 44%, by TC8.

TABLE 2 Treatment chemical screening and assessment for System 2. KHIAq. Polymer dose polymer removed (mass (mass (mass PTCPT PTFT System %)%) TC %) (° C.) (° C.) System 2 5.0 0.86 TC7 55 41 >90 KHI only 5.0 0.86TC7A 63 43 >90 5.0 0.86 TCBA 64 39 >90 5.0 0.86 TC8 44 43 >90 System 25.0 0.86 TC7 50 46 >90 KHI only 5.0 0.86 TC7A 64 43 >90 50° C. System 25.0 0.86 TC7 50 41 >90 1250 ppm 5.0 0.86 TC7A 57 43 >90 corrosioninhibitor System 2 5.0 0.86 TC7 46 28 >50 10% NaCl 5.0 0.86 TC7A 6029 >50 System 2 5.0 0.86 TC7 56 30 >90 20% 5.0 0.86 TC7A 53 35 >90 MEGSystem 2 5.0 0.86 TC7 64 N/A N/A 2x treated 5.0 0.86 TC7A 64 N/A N/A

The KHI from System 2 is known to be composed of at least two types ofpolymers. The results shown in Table 2 indicate that each TC may havebeen generally more successful at removing one or more of the KHIpolymers than the other(s). The post-treatment fouling temperature testsfurther support this hypothesis. In all treated System 2 samples, nofouling was observed below 90° C., and cloud points were observed at39-43° C. The observed cloud points are believed to be due to remnantglycol ether, a solvent in some KHI formulations, which is immisciblewith water at higher temperatures.

Based on the results of these screening tests, TC7 was selected forfurther assessment. TC7 was the most effective TC for both System 1 andSystem 2 in terms of KHI removal capability and elimination ofpost-treatment fouling at high temperature. TC7, which is chemicallysimilar to TC7A but with a different functional group, was selected as abackup for further assessment. TCBA, which showed generally goodperformance, is a solid and thus may need more complex formulation inorder to be more readily useful.

Further tests were conducted on System 2 samples to assess the effect oftemperature, corrosion inhibitors, salinity, solvents, and re-treatmenton the KHI removal effectiveness of TC7 and TC7A. Results of these testsare shown in Table 2 (above).

To assess the effect of high temperature on KHI removal, System 2samples were treated with TC7 or TC7A at 50° C. As can be seen fromTable 4, the higher treatment temperature did not have a significanteffect on KHI removal. No fouling was observed up to 90° C. Theseresults are consistent with the theory that the KHI in System 2 iscomposed of multiple polymers, at least one of which has a high drop-outtemperature and is thus difficult to remove from aqueous solution.Because this polymer is difficult to remove from aqueous solution, evenat high temperature, a high fouling temperature was observed, indicatingthat potential fouling issues posed by this polymer during waterhandling or re-injection are relatively low.

To assess the effect of the presence of a corrosion inhibitor on KHIremoval, System 2 samples were treated with TC7 or TC7A in the presenceof a commercially available corrosion inhibitor. As can be seen fromTable 2, the presence of the corrosion inhibitor slightly reduced theKHI removal effectiveness of both TCs. For instance, the mass percent ofKHI removed by TC7A fell from 64% (without corrosion inhibitor) to 57%.No fouling was observed up to 90° C.

To assess the effect of the presence of saline on KHI removal, System 2samples were treated with TC7 or TC7A in the presence of 10% by weightsodium chloride (NaCl). As can be seen from Table 2, the presence ofsaline slightly reduced the KHI removal effectiveness of both TCs. Forinstance, the mass percent of KHI removed by TC7A fell from 64% (withoutNaCl) to 60%. Cloud point temperatures were reduced to about 28-29° C.In addition, these samples exhibited a small degree of solids depositionwhen heated following TC treatment. A fine suspension of solid particlesbegan to appear around 50° C. As the samples were heated further, thefine solid particles coagulated into a small, semi-solid material thatfloated on the water, which had almost completely clarified.

To assess the effect of the presence of monoethylene glycol (MEG), acommon KHI solvent, on KHI removal, System 2 samples were treated withTC7 or TC7A in the presence of 20% by weight MEG. As can be seen fromTable 2, the presence of MEG slightly reduced the effectiveness of bothTCs. For instance, the mass percent of KHI removed by TC7A fell from 64%(without MEG) to 53%. Cloud point temperatures were reduced to about30-35° C. No fouling was observed up to 90° C., suggesting that any KHIpolymers that may present potential fouling problems were largelyremoved.

To examine whether additional KHI can be removed by multiple TCtreatments, System 2 samples were treated twice with the same TC (eitherTC7 or TC7A). Specifically, each sample was treated as described above,following which the treated aqueous phase was separated and treatedagain. As can be seen from Table 2, the mass percent of KHI removed byboth TC7 and TC7A was 64%, indicating that re-treatment can improve KHIremoval. These results also indicate that a maximum removal thresholdmay exist for a given combination of KHI and TC. These results areconsistent with the theory that the System 2 KHI is composed of multiplepolymers, one or more of which are largely removed by re-treatment andthe other(s) of which remain in aqueous solution.

Other implementations are also within the scope of the following claims.

What is claimed is:
 1. A method comprising: receiving a water streamfrom a hydrocarbon production facility, the water stream having a firstconcentration of a kinetic hydrate inhibitor (KHI); flowing the waterstream through a heat exchanger to heat the water stream to a targettemperature between about 70° F. and about 160° F.; mixing the heatedwater stream with a treatment chemical to form a two-phase mixture, thetreatment chemical having an affinity for the KHI; flowing the two-phasemixture into a separator; and physically separating the two-phasemixture into a first phase and a second phase, the first phase includingwater and having a second concentration of the KHI less than the firstconcentration, and the second phase including the KHI and the treatmentchemical, the density of the second phase being less than the density ofthe first phase.
 2. The method of claim 1, wherein receiving the waterstream comprises: receiving a fluid stream from the hydrocarbonproduction facility; and separating the fluid stream into a hydrocarbonstream and the water stream.
 3. The method of claim 2, furthercomprising separating the fluid stream into the hydrocarbon stream, thewater stream, and a gas stream.
 4. The method of claim 1, wherein thereceived water stream is at a first temperature, and wherein the targettemperature is at least 5° F. greater than the first temperature.
 5. Themethod of claim 1, wherein flowing the water stream through a heatexchanger comprises heating the water stream to a temperature sufficientto cause at least some of the KHI to precipitate from the water stream.6. The method of claim 1, wherein mixing the heated water stream with atreatment chemical comprises adding the treatment chemical to the waterstream such that a ratio of the treatment chemical to the KHI is between1 and
 3. 7. The method of claim 1, wherein physically separating thetwo-phase mixture comprises performing a gravity separation.
 8. Themethod of claim 1, wherein physically separating the two-phase mixturecomprises retaining the two-phase mixture in the separator for between 6hours and 24 hours.
 9. The method of claim 1, further comprisingprocessing the first phase to remove residual KHI.
 10. The method ofclaim 9, wherein processing the first phase comprises generating a thirdphase having a third concentration of KHI, the third concentration beingless than the second concentration.
 11. The method of claim 1, furthercomprising removing the KHI from the second phase.
 12. The method ofclaim 11, comprising: adding a condensate to the second phase; andremoving the KHI from the second phase including the condensate.
 13. Themethod of claim 11, further comprising returning the second phase or KHIseparated from the second phase to an upstream destination in thehydrocarbon processing or production facility for reuse.
 14. The methodof claim 1, wherein the treatment chemical is substantially immisciblewith water.
 15. The method of claim 1, wherein the treatment chemicalcomprises a functional group that has an affinity for a component of theKHI.
 16. The method of claim 1, wherein the second concentration is atleast about 40% less than the first concentration.
 17. The method ofclaim 1, wherein a cloud point temperature of the first phase is atleast 40° C.
 18. The method of claim 1, wherein a fouling temperature ofthe first phase is at least 90° C.
 19. The method of claim 1, whereinmixing the heated water stream with a treatment chemical comprisesmixing the heated water stream, the treatment chemical, and an organicacid.
 20. The method of claim 1, wherein mixing the heated water streamwith a treatment chemical comprises mixing the heated water stream, thetreatment chemical, and a saline solution.